Sour gas and acid natural gas separation membrane process by pre removal of dissolved elemental sulfur for plugging prevention

ABSTRACT

Methods for removing sulfur from a gas stream prior to sending the gas stream to a gas separation membrane system are provided. Two schemes are available. When the sulfur content is high or flow is relatively high, a scheme including two columns where one tower is regenerated if the sulfur concentration exceeds a preset value can be used. When the sulfur content is low or flow is relatively low, a scheme including one column and an absorption bed.

CROSS-REFERENCE TO RELATED APPLICATIONS

This patent application is a divisional application of U.S. patentapplication Ser. No. 12/916,701, filed on Nov. 1, 2010, now U.S. Pat.No. 8,540,804, and a divisional application of U.S. patent applicationSer. No. 13/975,935, filed on Aug. 26, 2013. For purposes of UnitedStates patent practice, this application incorporates the contents ofthe prior Applications by reference in their entirety.

FIELD OF THE INVENTION

This invention relates to methods for removing sulfur from gas streamsprior to sending the gas streams to gas separation membranes.

BACKGROUND OF THE INVENTION

Natural gas streams can contain dissolved elemental sulfur and releaseit in the casing or downstream the well head if subjected to changes incomposition, temperature, or pressure. In the case of gas separationmembranes, gas separation is based on the ability of a thin polymerlayer to discriminate molecules either on their size or theirsolubility. Irrelevant of the mechanism used in permeation, a change ingas composition and pressure can occur. The change in pressure alsogenerally induces a cooling effect that also induces a change intemperature. Depending upon the gas composition, pressure, andtemperature, the dissolved elemental sulfur in natural gas could depositin the membrane module due to the intrinsic changes in gas composition,pressure, and temperature in the membrane separation process. Indeed,retentate and permeate streams exhibit lower solubility of sulfur thanfeed and this phenomenon leads to sulfur deposition within the membranesystem resulting either in a blockage or membrane module breakage andfinally discontinuity in the operation.

Membrane based gas separation is also a well-known process used toremove or concentrate H₂S, CO₂, H₂, CO, N₂, and O₂ from streams.Polymeric gas membrane systems have been used in refineries,petrochemical plants, natural gas fields, and the like. The preferredmembranes for many applications are those systems have been usedoffering high selectivity and fluxes. For example, U.S. Pat. Nos.6,572,679; 6,361,583; 6,361,582; 6,723,152; 6,579,341; 6,565,626;6,592,650; and 6,896,717 describe the chemistry of such membrane systemsand processes that demonstrate their performance.

Several types of technology exist for absorbing or removing sulfur fromstreams. For example, the technology and the solvent chemistry toselectively absorb sulfur in natural gas stream are well known in theart. For instance, U.S. Pat. Nos. 5,028,343; 5,585,334; 4,804,485; andWO 2008/027381 describe solvent chemistry that can selectively absorbsulfur in natural gas streams. These solvents can be refreshed orchanged when the load in sulfur impairs a proper absorption of sulfurfor given flows and contactor design. The sulfur content in the solventis also well known in the art, and an on-line measurement system ispreferred such as on line X-ray fluorescence technique.

As another technology used to separate sulfur from a gas stream, sulfursolubility in hydrocarbon, carbon dioxide and hydrogen sulfide gasmixture has been investigated by others An example process using thistype of technology is described in U.S. Pat. No. 6,565,626.

U.S. Pat. Nos. 5,401,300; 5,407,467; and 5,407,466 describe only sourgas treatment processes for removal of H₂S, but not the dissolved sulfurin natural gas. U.S. Pat. No. 5,585,334 describes the dissolution ofsulfur from the sulfur deposits and sulfur plugs in gas wells, oilwells, vessels or conduits for transporting fluids containing sulfur.

Although many patents describe processes for removing H₂S or sulfur fromgas streams, a need exists for processes to help prevent sulfurdeposition in gas separation membrane systems. It would be advantageousif the processes could prevent loss of production, as well.

SUMMARY OF THE INVENTION

In view of the foregoing, a sour natural gas separation membrane processis provided in which natural gas is first passed through a solventscrubber to selectively absorb elemental sulfur in natural gas streamand then passed through a coalescing filter to remove entrained liquiddroplets before passing the natural gas through gas separationmembranes. These solvents can be refreshed or changed when the load insulfur impair a proper absorption of sulfur for given flows andcontactor design. Once the solvent becomes saturated, the solvent can bechanged. The sulfur content and solubility of sulfur in the solvent iswell documented in the art. Setting a cleaning frequency is difficultbecause the sulfur content in gas can vary due to changes in processconditions upstream of the unit. To alleviate this problem, an on-linemeasurement system can be used, such as on line X-ray fluorescencetechnique, to predict the amount of sulfur in the natural gas todetermine when the solvent scrubber needs to be regenerated or changed.

More specifically, methods of removing sulfur from a gas stream areprovided as embodiments of the present invention. In an embodiment ofthe present invention, a method of removing sulfur from a gas stream isprovided. In this embodiment, the gas stream is contacted with a solventto selectively absorb at least a portion of elemental sulfur from thegas stream such that the gas stream has a sulfur concentration that issubstantially less than prior to the gas stream being contacted with thesolvent. Entrained liquid droplets are then filtered and coalesced fromthe gas stream so that the elemental sulfur does not become deposited ona gas separation membrane. The gas stream is then passed through the gasseparation membrane. This embodiment of the present invention isparticularly useful when the sulfur concentration in the gas stream isrelatively high.

Another method of removing sulfur from a gas stream is provided asanother embodiment of the present invention. In this embodiment, the gasstream is contacted with a solvent to selectively absorb at least aportion of elemental sulfur from the gas stream. The entrained liquiddroplets are then filtered and coalesced from the gas stream. The gasstream is then passed through gas separation membranes. In thisembodiment, one absorber is in use and the second one in regenerationfor a continuous process. A gas stream sulfur concentration of anoverhead stream of the solvent of an exhaust/exit gas from the scrubberis then analyzed and the gas stream is sent to a second column if thesulfur concentration exceeds the sulfur solubility estimated in theretentate and permeate flows by membrane separation process simulationincluding the provision for inaccurate measurements and estimation. Thesolvent scrubber that is not in use is regenerated by sending a gascapable of dissolving sulfur through the solvent scrubber. Thisembodiment of the present invention is particularly useful when thesulfur concentration in the gas stream is relatively high.

As yet another embodiment of the present invention, a method of removingsulfur from a gas stream is provided. In this embodiment, the gas streamis cooled enable removing liquid in a knockout drum and hence producinga gas stream without liquids while entering the membrane module. The gasstream is then contacted with a solvent to selectively absorb at least aportion of elemental sulfur from the gas stream. The gas stream withoutliquids is contacted with an absorbent bed to removed sulfur in excessof solubility. A gas stream sulfur concentration in the gas streamwithout liquids is then analyzed to determine if the sulfurconcentration exceeds the sulfur solubility estimated in the retentateand permeate flows by membrane separation process simulation includingthe provision for inaccurate measurements and estimation. The gas streamwithout liquids is then passed through gas separation membranes. Thisembodiment of the present invention is particularly useful when thesulfur concentration in the gas stream is relatively low or the gasstream flow rate is relatively low.

Embodiments of the present invention alleviate many of the drawbacksassociated with prior art systems by providing a pre-conditioningtreatment of the gas stream by flowing the gas stream in a sulfursolvent contactor that will prevent both sulfur deposit and loss ofproduction. As a consequence, the gas separation by membrane technologyis more reliable and can offer a higher life expectancy.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above-recited features, aspects andadvantages of the invention, as well as others that will becomeapparent, are attained and can be understood in detail, more particulardescription of the invention briefly summarized above can be had byreference to the embodiments thereof that are illustrated in thedrawings that form a part of this specification. It is to be noted,however, that the appended drawings illustrate some embodiments of theinvention and are, therefore, not to be considered limiting of theinvention's scope, for the invention can admit to other equallyeffective embodiments.

FIG. 1 provides a schematic diagram of one embodiment of the presentinvention that can be used when a high concentration of sulfur ispresent in the gas stream.

FIG. 2 provides a schematic diagram of one embodiment of the presentinvention that can be used when a low concentration of sulfur is presentin the gas stream or if the gas stream has a low flow rate.

FIG. 3 provides a schematic diagram that is FIG. 4 of U.S. Pat. No.6,565,626, which is in accordance with prior art embodiments.

DETAILED DESCRIPTION OF THE INVENTION

Although the following detailed description contains many specificdetails for purposes of illustration, it is understood that one ofordinary skill in the art will appreciate that many examples, variationsand alterations to the following details are within the scope and spiritof the invention. Accordingly, the exemplary embodiments of theinvention described herein and provided in the appended figures are setforth without any loss of generality, and without imposing limitations,relating to the claimed invention.

Embodiments of the present invention include methods that can be used topre-condition a gas stream by flowing the gas stream in a sulfur solventcontactor that will prevent both sulfur deposition on downstreamequipment and subsequent loss of production. The use of the methods ofthe present invention are particularly advantageous when used incombination with gas separation membrane systems. As a consequence ofusing the methods of the present invention, the gas separation bymembrane technology is more reliable and offers a higher life expectancythan without the pre-conditioning of the gas stream.

In an embodiment of the present invention, a method of removing sulfurfrom a gas stream is provided. In this embodiment, the gas stream iscontacted with a solvent to selectively absorb at least a portion ofelemental sulfur from the gas stream such that the gas stream has asulfur concentration that is substantially less than prior to the gasstream being contacted with the solvent. Entrained liquid droplets arethen filtered and coalesced from the gas stream so that the sulfur doesnot become deposited on a gas separation membrane. The gas stream isthen passed through a gas separation membrane. This embodiment of thepresent invention is particularly useful when the sulfur concentrationin the gas stream is relatively high.

In embodiments of the present invention, the step of contacting the gasstream with a solvent can occur in a solvent scrubber. In an aspect, thestep of contacting the gas stream with a solvent can occur when the gasstream is flowing upstream and the solvent is flowing downstream countercurrently to the gas stream.

Various types of process equipment can be used when filtering entrainedliquid droplets from the gas stream. In an aspect, the step of filteringentrained liquid droplets can occur in a coalescing filter. Othersuitable types of process equipment that are capable of filtering theentrained liquid droplets will be apparent to those of skill in the artand are to be considered within the scope of the present invention.

In embodiments of the present invention, the methods of removing sulfurfrom a gas stream can also include the step of regenerating the solventscrubber by sending a gas capable of dissolving sulfur through thesolvent scrubber. In an aspect, the gas capable of dissolving sulfurcomprises hydrogen sulfide recovered from the gas separation membrane.Besides hydrogen sulfide, acid rich gases generated from the acid gasremoval system (i.e., amine treatment) can also be used to dissolvesulfur. Other suitable types of gases that are capable of dissolvingsulfur will be apparent to those of skill in the art and are to beconsidered within the scope of the present invention.

Besides regenerating the solvent, a continuous filtering system could beused to remove sulfur from the gas stream. Other suitable methods forremoving sulfur from the gas stream will be apparent to those of skillin the art and are to be considered within the scope of the presentinvention.

The operating parameters of the equipment can be varied depending uponthe concentration of sulfur in the stream. Other process conditions canalso affect the suitable operating conditions for the processesdescribed in the present invention. For example, in an aspect, the stepof regenerating the solvent scrubber can occur at any pressure that iscapable of compensating for the pressure loss in the regeneration towerand/or piping. As another example, the step of contacting the gas streamwith the solvent occurs at a pressure substantially similar to a feedgas pressure of the gas stream. Other suitable operating pressures canbe used, as will be apparent to those of skill in the art, and are to beconsidered within the scope of the present invention.

In an aspect, the solvent regeneration gas comprises hydrogen sulfide.Other suitable solvent regeneration gases will be apparent to those ofskill in the art and are to be considered within the scope of thepresent invention.

As the solvent continues to contact the gas stream, the sulfur contentin the solvent continues to increase. Once the sulfur content of thesolvent exceeds a preset value, the solvent scrubber should beregenerated. Various methods exist for determining the concentration ofsulfur contained in the overhead exit gas stream as it exits the solventscrubber. In embodiments of the present invention, the methods ofremoving sulfur from a gas stream can also include analyzing a gasstream sulfur concentration of an overhead exit stream of the solventscrubber and sending the gas stream to a second column if the sulfurconcentration exceeds the sulfur solubility estimated in the retentateand permeate flows by membrane separation process simulation includingthe provision for inaccurate measurements and estimation. In an aspect,an X-ray analyzer can be used to measure the sulfur content of theoverhead/exit stream. In other aspects, raman-laser or gaschromatography with a sulfur sensor can be used to measure the sulfurcontent of the overhead/exit stream. Other suitable methods of measuringthe sulfur content of the overhead/exit stream will be apparent to thoseof skill in the art and are to be considered within the scope of thepresent invention.

Another method of removing sulfur from a gas stream is provided as anembodiment of the present invention. In this embodiment, the gas streamis contacted with a solvent to selectively absorb at least a portion ofelemental sulfur from the gas stream. The entrained liquid droplets arethen filtered and coalesced from the gas stream the sulfur does notbecome deposited on a gas separation membrane. The gas stream is thenpassed through the gas separation membrane. In this embodiment, oneabsorber is in use and the second one is in regeneration for acontinuous process. A gas stream sulfur concentration of an overheadstream of the solvent scrubber is then analyzed and the gas stream issent to a second column if the sulfur concentration exceeds the sulfursolubility estimated in the retentate and permeate flows by membraneseparation process simulation including the provision for inaccuratemeasurements and estimation. The solvent scrubber not in use isregenerated by sending a gas capable of dissolving sulfur through thesolvent scrubber. This embodiment of the present invention isparticularly useful when the sulfur concentration in the gas stream isrelatively high.

The process 10 shown in FIG. 1 can be utilized and is preferred when theconcentration of sulfur in the gas stream 15 and or flow to be treatedis high. For purposes of FIG. 1, S=solvent; P₁, P₂=purges;X═X_(ray)-sulfur concentration; F=filter-coalescer; M=membrane unit;Re=retentate; and Pe=permeate. This embodiment typically includes twotowers 20, 25 and is operated as a continuous process.

Solvent 30 in the first tower 20 absorbs the sulfur from the gas stream15 while the second solvent tower 25 is used in a regeneration step.These are two separate systems operating in embodiments of the presentinvention. In the first system, the absorption tower 20 operates at feedgas pressure, while the regeneration tower 25 in the second systemoperates at low pressure. The gas stream 15 flows upstream in theabsorption tower 20, which is equipped with packings or trays. The gasstream 15 can be sent to a chiller prior to the absorption tower 20 tolimit the quantity of entrained liquid in the gas stream 15 and tomaximize the solvent absorption of sulfur in the gas stream 15, ifneeded. The solvent 30 flows downstream counter currently to the gasstream 15, which absorbs the sulfur contained in the gas stream 15. Thesolvent 30 sulfur loading increases along the run. An on-line analyzer X(X-ray for example) allows measuring the sulfur concentration in theexit gas stream 35 at the exit of the absorption column 20 and beforethe membrane unit 40. The analyzer X can send an alarm as soon as thesulfur content in the exit gas stream 35 exceeds a preset value. Thepreset value can be the sulfur solubility estimated in the retentate andpermeate flow streams by membrane separation process simulationincluding the provision for inaccurate measurements and estimation. Themaximum amount of sulfur that can be present is the amount that enablessulfur absorption to prevent the sulfur concentration in the overheadgas to exceed the sulfur solubility in retentate and permeate flowstreams. In an aspect, the amount of sulfur in the exit gas stream 35can range from less than about 1 ppmV to about 350 ppmV.

If the sulfur content of the exit stream 35 exceeds the preset value,the gas feed 15 is then sent to the second column 25 while the firstabsorption column 20 is subjected to regeneration mode. In theregeneration mode at low pressure, the H₂S concentrated gas stream 45separated in the membrane unit 40 is used to recover the sulfur from theloaded solvent 30. H₂S is well known as an efficient solvent forelemental sulfur. The H₂S and sulfur gas stream will then be treated bya classical recovery unit, such as a Claus process that is eventuallyfollowed by a tail gas unit for extreme sulfur recovery. Other suitablemethods for recovering sulfur, such as precipitation, filtration, andthe like, will be apparent to those of skill in the art and are to beconsidered within the scope of the present invention.

A new cycle for the two columns 20, 25 begins as soon as the sulfurconcentration in the exit gas stream 35 arriving at the analyzer Xexceeds the pre-set value. Other components, such as water and heavyhydrocarbons, will also be absorbed to a certain extent by the solvent30. Periodically, a purge P is sent to a three phase separator and lostsolvent is replaced by fresh solvent from the solvent tank S. The gasstream 50 with very low sulfur content is then treated in the membraneunit 40. In the membrane unit 40, the gas stream 50 goes to afilter-coalescer F to remove droplets of entrained liquids, solvent andsome water in the purge P followed by heat exchanger 55. Heat exchanger55 can reheat the gas stream 50, if needed, to ensure a gaseous streamis sent to the membrane module M. Separation of methane from othercomponents, such as N₂, H₂S, CO₂, H₂O, C₂ ⁺, and the like, takes placein membrane modules M. More concentrated gases exit the unit as permeatestream Pe and retentate stream Re for further processing in the gasplant.

Various types of solvents can be used in embodiments of the presentinvention. In an aspect, the solvent is polyethylene glycol, ethers ofpolyethylene glycol, polypropylene glycol, ethers of propylene glycol,n-methylpyrolidone, n-ethyl pyrolidone, n-cyclohexyl pyrolidone,n-phenyl morpholine, n-cyclohexyl morpholine, dimethyl disulfur,dimethyl-sulfur, carbon disulfide, xylene, toluene, BTX (mixture ofbenzene, toluene, and xylene), kerosene, naphthalene, alkyl-naphthalene,or combinations thereof. The solvent can be a member of the glycolfamily, such as polyethylene glycol, polypropylene glycol, and theirrelated ethers (methyl, ethyl, etc.). The solvent can be a member of thepyrolidone family, such as N-methyl pyrolidone, N-ethyl pyrolidone,N-cyclohexyl pyrolidone, combinations thereof, and the like. The solventcan be a member of the morpholine family, such as n-phenyl morpholine,n-cyclohexyl morpholine, combinations thereof, and the like. The solventcan include an organic sulfur solvents, such as dimethyl-di-sulfur,dimethyl-sulfur, carbon disulfide, or be a sulfur containing solventhaving the formula R—Sn—R, wherein R can be hydrocarbyl radical from 1to 30 carbons, or alternatively, from 2 to 10 carbons, or alternatively,from 2 to 5 carbons. Other suitable organic solvents can include xylene,toluene, BTX, kerosene, naphthalene, alkyl-naphthalene, and the like.Other suitable types of solvents that can be used in embodiments of thepresent invention will be apparent to those of skill in the art and areto be considered within the scope of the present invention.

The size of the absorption tower 20 can vary depending upon theanticipated flowrate of the gas stream 15, as will be apparent to thoseof skill in the art. The absorbent tower 20 can also be used to reclaimthe solvent solution periodically and then on a bypass of the secondtower 25.

As yet another embodiment of the present invention, as shown in FIG. 2,a method of removing sulfur from a gas stream is provided. In thisembodiment, the gas stream is cooled to enable removing liquid in aknockout pot and hence producing a gas stream without liquids whileentering the membrane module M. The gas stream is then contacted with asolvent to selectively absorb at least a portion of elemental sulfurfrom the gas stream. The gas stream without liquids is contacted with anadsorbent or a filter to remove sulfur in excess of solubility. A sulfurconcentration in the gas stream without liquids is then analyzed todetermine if the sulfur concentration exceeds the sulfur solubilityestimated in the retentate and permeate flows by membrane separationprocess simulation including the provision for inaccurate measurementsand estimation. The gas stream is sent to a heat exchanger followed by afilter-coalescer to remove droplets of entrained liquids. The gas streamwithout liquids is heated in heat exchanger, if needed, to ensure agaseous stream is sent to the membrane modules. The gas stream withoutliquids is then passed through gas separation membranes M.

The process 110 shown in FIG. 2 can be utilized when the concentrationof sulfur in the gas stream 115 and or flow to be treated is low. Withrespect to FIG. 2, S=solvent; P₁, P₂=purges; X=Xray-sulfurconcentrations; A=adsorbent; F=filter-coalescer; M=membrane unit;Re=retentate; and Pe=permeate.

More specifically, in the process 110 shown in FIG. 2, the gas stream115 flows upstream in a column 120 equipped with packings or trays. Thesolvent 130 flows downstream counter currently to the gas stream 115 andabsorbs the sulfur contained in the gas stream 115. Then the loadedsolvent 130 is pumped, chilled and passes through a bed of adsorbent Awhere the sulfur in excess of solubility is trapped. Alternatively, afilter could be used instead of adsorbent A after precipitation ofsulfur due to the temperature decrease. The adsorbent containing sulfuris periodically removed and replaced, which is considered as a waste. Anon-line analyzer X (X-ray for example) allows measuring the sulfurconcentration in the exit gas stream 135 before it is sent to themembrane unit 140. The analyzer X can send an alarm for adsorbentreplacement as soon as the sulfur content exceeds the sulfur solubilityestimated in the retentate and permeate flows by membrane separationprocess simulation including the provision for inaccurate measurementsand estimation. Other components like water and heavy hydrocarbons willalso be absorbed to a certain extent by the solvent 130. Periodically,purges P₁ and P₂, can be sent to a three phase separator and can bereplaced by fresh solvent from the solvent tank S. Heavy HC can berecovered from the purges P₁ and P₂ in a three way separator. The gasstream 150 with very low sulfur content is then treated in the membraneunit 140. In the membrane unit 140, the gas stream 150 is sent to afilter-coalescer F to remove any entrained liquid droplets, solvent andsome water in the purge P followed by a heat exchanger 155. Separationof methane from other components, such as N₂, H₂S, CO₂, H₂O, C₂ ⁺, andthe like, takes place in membrane modules M. More concentrated gasesexit the unit as permeate stream Pe and retentate stream Re for furtherprocessing in the gas plant.

Various types of adsorbent materials can be used in embodiments of thepresent invention. In an aspect, the adsorbent bed contains activatedcarbon, supported metallic oxides, supported organic oxides, orcombinations thereof. Other suitable types of adsorbent materials thatcan be used in embodiments of the present invention will be apparent tothose of skill in the art and are to be considered within the scope ofthe present invention. When a filter is used to remove sulfur from theloaded solvent 130, the filter can include supported metallic filters,supported organic filters, polymeric filters, or combinations thereof.Other suitable types of filters that can be used in embodiments of thepresent invention will be apparent to those of skill in the art and areto be considered within the scope of the present invention.

As an advantage of the present invention, the frequency of regeneratingthe solvent scrubber can be easily determined. Setting cleaningfrequency based upon other factors, such as run time, is difficultbecause the sulfur content in the gas stream can vary due to changes inprocess conditions upstream of the unit. Sampling can also be used tomonitor solvent regeneration frequency. Use of an on-line measurementsystem, such as on line X-ray fluorescence technique, as used inembodiments of the present invention, can be utilized to determine theamount of sulfur in the gas stream to determine the frequency in whichthe solvent scrubber should be regenerated.

EXAMPLE

Prior art processes used to removed sulfur from streams do not describeor take into account gas membrane separation processes and ways toprevent the sulfur deposition within the membrane system resultingeither in a blockage or membrane module breakage, eventual discontinuityin the operation membrane separation process, and loss of productionarising due to solubility evolution along membrane separation process.

Polymeric membrane based gas separation has been used in refineries,petrochemical plants, natural gas fields, and the like. The preferredmembranes for many applications are the ones offering high selectivityand fluxes. For example, U.S. Pat. Nos. 6,572,679; 6,361,583; 6,361,582;6,723,152; 6,579,341; 6,565,626; 6,592,650; and 6,896,717 describe thechemistry of such membrane gas separation processes.

Sulfur solubility in hydrocarbon, carbon dioxide, and hydrogen sulfidegas mixture has been investigated by others. In the present invention,simulation models were developed to assess the amount of sulfur that canbe dissolved in a gas mixture for a given composition, pressure, andtemperature.

The membrane gas separation scheme shown in FIG. 3 is from U.S. Pat. No.6,565,626 (hereinafter “the '626 patent”). Table 26 of the '626 patentis also included which provides example operating conditions for theprocess shown in FIG. 3. Table 26 shows the gas composition for feed,permeate, and retentate streams for different stages. Tables 1 and 2contain the data, sulfur solubility and maximal sulfur concentration forthe different streams obtained by the simulation models developed inaccordance with embodiments of the present invention.

TABLE 26 Stream 201 202 203 204 205 206 207 208 209 Flow (MMscfd) 10.014.2 14.2 6.2 8.0 1.2 6.8 3.2 3.0 Temp. (° C.) 50 38 25 16 7 4 2 13 10Pressure (psia) 200 200 1,200 200 1,200 200 1,200 20 200 Component (mol.%): Nitrogen 5.0 5.3 5.3 7.4 3.7 6.5 3.2 8.8 5.8 Methane 80.0 83.5 83.568.9 94.8 88.2 96.0 46.0 93.2 Carbon Dioxide 15.0 11.2 11.2 23.8 1.5 5.30.8 45.2 1.0

TABLE 1 Gas stream composition, sulfur solubility evolution alongmembrane separation as depicted in U.S. Pat. No. 6,565,626 in accordancewith embodiments of the present invention Stream 201 202 203 204 205 206207 208 209 Flow (MMscfd) 10 14.2 14.2 6.2 8 1.2 6.8 3.2 3.0 Temp (° C.)50 38 25 16 7 4 2 13 10 Pressure (psia) 200 200 1,200 200 1,200 1,200 20200 200 Nitrogen (mol %) 5 5.3 5.3 7.4 3.7 6.5 3.2 8.8 5.8 Methane (mol%) 80 83.5 83.5 68.9 94.8 88.2 96.0 46.0 93.2 Carbon Dioxide 15 11.211.2 23.8 1.5 5.3 0.8 45.2 1.0 (mol %) Maximal Sulfur 0.0698 0.01690.0210 0.00094 0.00458 .00016 0.0031 0.0029 0.00039 Contents (mg/Nm³)Maximal Sulfur 19.77 6.80 8.44 0.16 1.03 0.005 0.605 0.262 0.0338 Flow(g/d)

TABLE 2 Gas stream composition, sulfur solubility evolution alongmembrane separation as depicted in U.S. Pat. No. 6,565,626 where CO₂ isreplaced by H₂S and assuming similar permeability for H₂S and CO₂ inaccordance with embodiments of the present invention Stream 201 202 203204 205 206 207 208 209 Flow (MMscfd) 10 14.2 14.2 6.2 8 1.2 6.8 3.2 3.0Temp (° C.) 50 38 25 16 7 4 2 13 10 Pressure (psia) 200 200 1,200 2001,200 200 1,200 20 200 Nitrogen (mol %) 5 5.3 5.3 7.4 3.7 6.5 3.2 8.85.8 Methane (mol %) 80 83.5 83.5 68.9 94.8 88.2 96.0 46.0 93.2 Hydrogensulfide 15 11.2 11.2 23.8 1.5 5.3 0.8 45.2 1.0 (mol %) Maximal Sulfur3.55 1.55 1.94 1.12 0.11 0.12 0.05 1.52 0.03 Contents (mg/Nm³) Sulfur1004 622 780 197 25 4.3 9.4 138 2.9 Flow (g/d)

As shown in Table 1 and Table 2, sulfur contained in natural gas coulddepose in the membrane module due to the changes in gas composition,pressure, and temperature, which are intrinsic changes in the membraneseparation process. Indeed, retentate and permeate streams exhibit lowersolubility than feed and it is believed that this phenomenon leads tosulfur deposition within the membrane system resulting either in ablockage or membrane module breakage and finally discontinuity in theoperation. To overcome this problem, it was discovered that apre-conditioning of the gas by flowing the gas in sulfur solventcontactor will prevent both sulfur deposit and loss of production. As aconsequence of using the methods of the present invention, the gasseparation by membrane technology is more reliable and offer higher lifeexpectancy.

As shown in Tables 1 and 2, for lower and higher dissolved sulfurconcentrations in the natural gas stream, coalescing filters, which aretypically used in membrane gas separation processes, are not enough toprevent sulfur deposition within the membrane system. Thepre-conditioning of the gas by flowing the gas in sulfur solventcontactor coupled with coalescing filter preconditioning will preventboth sulfur deposit and loss of production due to solubility evolutionalong the membrane separation process. As indicated previously, majoradvantages of using the processes of the present invention are that thesour natural gas separation by membrane technology is more reliable andoffers a higher life expectancy.

Although the present invention has been described in detail, it shouldbe understood that various changes, substitutions, and alterations canbe made hereupon without departing from the principle and scope of theinvention. Accordingly, the scope of the present invention should bedetermined by the following claims and their appropriate legalequivalents.

The singular forms “a”, “an” and “the” include plural referents, unlessthe context clearly dictates otherwise.

Optional or optionally means that the subsequently described event orcircumstances may or may not occur. The description includes instanceswhere the event or circumstance occurs and instances where it does notoccur.

Ranges may be expressed herein as from about one particular value,and/or to about another particular value. When such a range isexpressed, it is to be understood that another embodiment is from theone particular value and/or to the other particular value, along withall combinations within said range.

Throughout this application, where patents or publications arereferenced, the disclosures of these references in their entireties areintended to be incorporated by reference into this application, in orderto more fully describe the state of the art to which the inventionpertains, except when these reference contradict the statements madeherein.

That which is claimed is:
 1. A method of removing sulfur from a gasstream comprising the steps of: a. cooling the gas stream to produce agas stream without liquids and a chilled solvent; b. contacting the gasstream without liquid with the chilled solvent to selectively absorb atleast a portion of elemental sulfur from the gas stream; c. contactingthe chilled solvent with an absorbent bed or a filter to remove sulfurin excess of solubility; d. analyzing a sulfur concentration in the gasstream without liquids to determine if the sulfur concentration exceedsa sulfur solubility estimated in retentate and permeate flows by amembrane separation process simulation; and e. passing the gas streamwithout liquids through gas separation membranes.
 2. The method of claim1 where the absorbent bed contains activated carbon, supported metallicoxides, supported organic oxides, or combinations thereof.
 3. The methodof claim 1 where the filter contains supported metallic filters,supported organic filters, polymeric filters, or combinations thereof.4. The method of claim 1 where the solvent is polyethylene glycol,ethers of polyethylene glycol, polypropylene glycol, ethers of propyleneglycol, n-methylpyrolidone, n-ethyl pyrolidone, n-cyclohexyl pyrolidone,n-phenyl morpholine, n-cyclohexyl morpholine, dimethyl disulfur,dimethyl-sulfur, carbon disulfide, xylene, toluene, BTX (a mixture ofbenzene, toluene, and xylenes), kerosene, naphthalene,alkyl-naphthalene, or combinations thereof.
 5. The method of claim 1further including the step of separating a heavy hydrocarbon stream fromthe gas stream without liquids prior to passing the gas stream withoutliquids through gas separation membranes.